随着油气开采水平段长度的增加，作业难度显著提高！ 编译 | 惊蛰 钻井团队一直致力于增加Marcellus页岩水平井的水平段长度。为了能够钻出超过*****英尺的水平段，并顺利下入套管，亟需改进作业方法。在为期**个月的改进与提升过程中，作业团队钻了**口水平井，每口井的水平段长度都超过了*****英尺，是Marcellus油田首批超过该长度的水平井。 在开发Marcellus油田以往作业中，该团队钻了数百口水平井，水平段长度从****至*****英尺不等，平均长度为****英尺。****年年底，业内重心转向了利用大位移水平井。这一规划上的改变，数十口井的水平段长度超过了*****英尺。因此，自****年开始，在新增的***口井中，水平段平均长度增加到了****英尺。 在最初几年的Marcellus水平井钻井作业中，使用的工具与方法可有效钻出****英尺以下的水平段。常规作业包括使用**** psi循环系统的钻机、弯外壳马达的定向工具、水基聚合物钻井液以及标准钻井程序。在后续的评估过程中，该团队关注的重点是每英尺水平段的钻进成本。提高性能以及保持稳定的整体钻井成本，有助于降低每英尺水平段的钻进成本。 作业团队先前重点研究了较短的水平段，并利用超级单臂钻机获得了成功，得益于这类钻机的多功能性与高效的设计。为了应对开发挑战，钻井队进行更新换代，采用了高性能的钻机，这些钻机都具有更强的水平井钻进能力。 ****年春，第一口*****英尺的水平段被提上了作业议程，准备在年底开钻。因此，需要升级钻机，以满足即将到来的更长水平段。钻机与设备的尺寸成为钻井队的另一个重要考虑因素，所选的高级钻机必须适用于这些现场。 在找到合适的候选方案以应对钻井设计的变更后，****年秋季，又增加了一台新钻机，其特点如下：*，****马力的绞车；*，****马力的泥浆泵（*.*寸缸套下，最高额定泵压为****psi）；，顶驱的最大钩载可达***吨；*，****千瓦的发电机；*，*寸外径钻杆； *，井架可承重**万磅，可排立*****英尺的钻杆。 当水平段平均长度达到****英尺时，有效滑动钻进并保持稳定的工具面变得尤为困难，井队通常使用振动工具（最初为钟摆工具）。然而，当水平段长度超过****英尺时，则需要一种不同类型的振动工具，该工具名为水力振荡器。这是一个安装在底部钻具组合上的井下工具，当流体被泵入工具时，通过轴向移动钻具，提高了滑动钻进的效率。振荡器使每次滑动与旋转变得更为有效，特别是与地面振动工具配合使用时。 然而在****年底，钻井计划将水平段长度增加至*****英尺甚至更高时，该团队对目前使用的定向工具进行了评估，确定需要旋转导向工具才能成功钻出这种长度的水平段。旋转导向工具可在钻柱旋转时提供导向，从而无需弯外壳与滑动钻进。在整个钻进过程中，管柱的完全旋转可降低钻杆与井眼间的摩擦。旋转导向又可以避免使用振动工具，消除了相关技术带来的额外风险。旋转导向工具在较小的靶点窗口内，也具有精确的定向导向能力。而且，更良好的井眼清洁状况，可提高机械钻速与井壁稳定性。 ****年之前，水基聚合物钻井液广泛用于*****英尺以下的水平段钻进作业。该体系采用高氯基钻井液，改善了钻进Marcellus页岩时钻井液的抑制性。而且，它还具有有效的流变性，可改善井眼清洁状况，并增加了添加剂以提高钻井液的润滑性。该体系能够有效应用于较短的水平段，但钻井队在早期的钻进开发项目中，遇到了几次井壁失稳的情况。从中吸取的主要经验教训表明，需要减少钻井液漏失，增加钻井液比重。 油基钻井液具有改善页岩抑制性与润滑性的特点。当与旋转导向工具配合使用时，可缩短清洁井眼与井筒的时间，从而在钻进水平段时，获得更大的成功。 ****年底，之所以能够在*万至*.*万英尺的水平段钻进作业中取得成功，归功于升级后的钻机，功率与额定作业压力都得到了提高，再加上旋转导向工具与油基钻井液的使用。而且，井壁稳定性也得到了显著提高。 得益于上述技术的进步，水平段进尺每天都在上涨。从****年初至撰写本文时,已有三十多天(**小时报告时间)的水平段进尺超过****英尺，甚至有两天的进尺超过了****英尺。这段时间的平均水平段进尺为****英尺，已经接近了****年的最高日进尺记录。 在下套管前，必须考虑增加的摩擦阻力。将下套管所受阻力进行建模分析，若是达到极限值，即套管无法下入至井底，则可以利用漂浮接箍来将套管下入至指定深度，且无需修改太多作业计划。 漂浮接箍可以策略性地置于套管柱中，以帮助套管漂浮至井底。在单钻井液体系中，漂浮接箍下方的套管都是空的（充满空气），漂浮接箍上方的套管内注满钻井液，以帮助转移载荷。在水平段内，套管内空气与井筒内钻井液的密度差，会对套管产生浮力作用，有助于将套管漂浮至井底。 根据所用漂浮接箍的类型，套管在预定的深度着陆后，打开或破碎漂浮接箍，使套管的下部充满钻井液。然后，持续循环钻井液，将井底空气循环至井口，以可控的方式将空气排出。之后，套管内全部充满钻井液，在注水泥固井作业前，继续循环钻井液，以改善井况。 随着水平段长度的增加，井眼清洁作业与参数也发生了变化。较短的水平段无需太过关注井眼清洁的相关作业，通常是重复标准化程序。随着水平段长度的不断增加，出现了诸多井筒问题。深入调查后确定，在钻井作业中，需要提高包括排量、转速在内的钻进参数。钻至完钻井深后，循环次数也会增加，以维持特定的参数。 除了清洁井眼的循环参数外，还需多关注起下钻作业。为了更快的下入套管、注水泥封固井筒，水平段较短的井侧重于快速起下钻的标准作业程序。随着水平段越来越长，当达到某个长度时，将会很难从井底起出钻具，因为所需的钩载已超过了钻井承包商的过提权限。在这些情况下，建议采用倒划眼的方法将钻具提离井底。头两口水平段超过*****英尺的水平井，当钻至完钻井深后，都是采用倒划眼方法起出钻具。 这两口井中存在井眼缩径，当起钻至该位置时，需要倒划眼才能继续起出钻具。在第三口超过*****英尺的水平段中，发生了卡钻，导致底部钻具组合落入井中。调查发现，事故发生时，起钻速度超过了推荐值，倒划眼起出钻具。即使倒划眼方法可将钻具起出井筒，但在如此之快的起钻速度下，钻具会被拉入岩屑床，最终导致粘卡。目前已实施了新的倒划眼标准，以限制倒划眼时的起钻速度。? A drilling team has focused on increasing lateral lengths in the Marcellus Shale. The team determined which operational practices would need to be revised in order to drill and case laterals in excess of **,*** ft. During a **-month period of revised processes and upgrades, the team drilled ** horizontal wells, each exceeding **,*** ft in lateral length, which represented the first Marcellus lateral to exceed that length. Introduction At the time of writing, the team had drilled more than *,*** Marcellus wells in the state of Pennsylvania. In the first decade of development (****–****), it drilled hundreds of Marcellus horizontal wells with laterals ranging from *,*** to **,*** ft. The average lateral length over that period was *,*** ft. In late ****, focus was placed on developing the core acreage of the Marcellus field with extended laterals. This change in planning resulted in dozens of wells being scheduled that would feature lateral lengths exceeding **,*** ft. As a result, the average lateral length increased to *,*** ft over a span of *** additional wells drilled starting in ****. Throughout the initial years of drilling Marcellus horizontal wells, tools and practices were used that efficiently drilled laterals under *,*** ft in length. Routine operations included use of rigs with *,***-psi circulating systems, directional tools with bent housing motors, saltwater-based polymer drilling fluids, and standard drilling procedures. In re-evaluating processes, the team focused on cost per lateral foot (Fig. *). Increased performance coupled with maintenance of consistent overall drilling costs helped lower the cost per lateral foot.? Rig Selection While focusing on what are now deemed as shorter laterals, the team had experienced success drilling with super single rigs because of their versatility and efficient design. The second iteration of a rig fleet to meet the challenges of developing the Marcellus Shale came in the form of high-performance rigs with new enhanced horizontal-drilling capabilities. The team used this style of rig to meet lateral-length challenges successfully from **** until late ****, drilling *** Marcellus horizontal wells in that time period. In the spring of ****, the first **,***?ft lateral was placed on the drilling schedule for the end of that same year. The rig fleet would need to be upgraded in order to meet the upcoming required changes in lateral length. Size of the rig and equipment became another critical consideration for the rig fleet, because, by then, returning to sites with actively producing wells had become routine, so the upgraded rigs selected would have to fit onto these sites. After finding suitable candidates that fit the change in the drilling program, an additional rig was added in the fall of **** that featured the following characteristics:*,***-hp drawworks *,***-hp mud pumps (*,***-psi maximum rated working pressure with *.*-in. liners) ***-ton topdrive (**,*** ft-lbf maximum continuous drilling torque capability) *,***-kW generators *-in.-outer-diameter drillpipe ***,***-lbm capacity mast, capable of racking back **,*** ft of drillpipeDirectional Tools As lateral-length average reached *,*** ft, the ability to slide drill effectively and hold consistent tool face suffered and the drilling team used oscillating tools (initially, a rocking tool). Drilling laterals greater than *,*** ft, however, required a different type of oscillating tool called an agitator. This is a downhole tool that is run on the bottomhole assembly (BHA) that increases the effectiveness of slide drilling by axially moving the drillstring as fluid is pumped through the tool. Agitators make each slide and rotate sequence more effective, especially when paired with surface oscillating tools. When the drilling schedule increased to **,*** ft and greater by the end of ****, however, the team evaluated the currently used directional tools and determined that rotary-steerable tools would be required to reach these lateral lengths. Rotary-steerable tools allow the drillstring to steer while rotating the entire drillstring, eliminating the need to have a bent housing and slide drill. Fully rotating the drillstring throughout the drilling process reduces the friction between the drillpipe and wellbore. Rotary-steerable capability eliminates the need to use oscillating tools and the additional risk associated with each technology. Rotary-steerable tools also have precise directional steering ability in tighter target windows. Improved wellbore cleaning leads to improved rate of penetration and wellbore stability. Drilling Fluids Saltwater-based polymer drilling mud was used widely on lateral lengths up to **,*** ft until ****. This system used a high-chloride-based mud for improved inhibition drilling through the Marcellus shale, with effective rheologies for hole cleaning and additives to improve lubricity. This system was effective on shorter lateral lengths, but the drilling team experienced several instances of instability as the program developed from the early stages of drilling. Major lessons learned pointed to fluid-loss reductions and mud-weight increases.? Diesel-oil-based muds feature improved shale inhibition and lubricity. When paired with rotary-steerable tools, the time spent on wells and wellbore cleaning is reduced, leading to greater lateral drilling success. By the end of ****, the upgraded rig fleet with improved rig horsepower and additional pressure rating, combined with rotary-steerable tools and diesel-oil-based drilling fluid, were crucial to the team’s success in drilling laterals between **,*** and **,*** ft. Wellbore stability dramatically improved. The changes resulted in a drastic increase in daily lateral footage per day. From the beginning of **** until the time of writing, there have been more than ** days (**-hour report time) that have exceeded *,*** lateral ft, including * days that have eclipsed *,*** ft. These days have pushed the daily lateral average above *,*** ft, which is close to the record day from ****. Casing Flotation When running a long string of casing, increased drag must be considered before the casing run is begun. If the drag associated with running casing is modeled to reach a critical limit in which the pipe will not be able to be slacked off to bottom, a casing flotation sub can be used to achieve a desired set depth with minimal operational changes. A flotation sub can be placed strategically in the casing string to aid in floating casing to bottom. With a single-drilling-fluid system, a specified length of casing is left empty (air-filled) with the area above the flotation sub filled with drilling fluid to aid in weight transfer. In the lateral, a buoyant effect on the casing caused by the difference between the drilling fluid and the air-filled portion of the casing helps float the casing to bottom. After the casing is landed at the desired set depth, depending on the type of flotation sub used, the sub is then opened or ruptured to allow the lower portion of the casing to fill with drilling fluid. The air is then allowed to swap with the now-drilling-fluid-filled portion of the casing string and circulated back to surface, where it is bled off in a controlled manner. Afterward, the void is fully filled back to surface and prejob circulations can begin to condition the wellbore before cementing the production casing string. Best Practices Hole-cleaning practices and parameters have changed as lateral lengths have increased. Shorter laterals saw less of a procedural focus on wellbore-cleaning practices. The drilling-engineering team typically reproduced standard procedures in well after well. As laterals continued to lengthen, an abnormal number of wellbore issues were encountered in **** and ****. An in-depth review determined that, while drilling, parameters including flow rates and rotational speed needed to be increased. After drilling to total depth (TD), the circulations increased with specific parameters to maintain. In addition to cleanup-cycle parameters, an added focus also was put on tripping procedures. Standard procedure for shorter laterals focused on fast tripping in order to get the wellbore cased and cemented in a short time. As laterals were extended, a point was reached at which pulling the drillstring off bottom without needing the drilling contractor’s overpull approval was unachievable. In those instances, back-reaming was the recommended method to get off bottom. The first two laterals exceeding **,*** ft required back-reaming to trip out of the hole once TD was reached. In both of those wells, while tripping out, the drillstring encountered tight hole spots where back-reaming was required to continue out of the hole. On the third **,***-ft lateral, back-reaming operations resulted in the drillstring sticking and leaving the BHA downhole. An investigation uncovered that the drillstring was being back-reamed out of the hole at higher-than-recommended speeds. Even with the drillstring being back-reamed out of the hole, at those speeds, it was pulled into a cuttings bed that ultimately packed off the BHA. New back--reaming standards were implemented to limit tripping speeds while back-reaming.